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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2003

OR

For the transition period from              to             

Commission file number 1-8590

MURPHY OIL CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (870) 862-6411

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨.

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x

Aggregate market value of the voting stock held by non-affiliates of the registrant, based on average price at January 31, 2004, as quoted by the New York Stock Exchange, was approximately $4,235,014,000.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act).    Yes  x    No  ¨.

Aggregate market value of the voting stock held by non-affiliates of the registrant, based on average price at June 30, 2003, as quoted by the New York Stock Exchange, was approximately $3,683,817,000.

Number of shares of Common Stock, $1.00 Par Value, outstanding at January 31, 2004 was 91,880,304.

Documents incorporated by reference:

Portions of the Registrant’s definitive Proxy Statement relating to the Annual Meeting of Stockholders on May 12, 2004 have been incorporated by reference in Part III herein.

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MURPHY OIL CORPORATION

TABLE OF CONTENTS – 2003 FORM 10-K

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PART I

Items 1. and 2. BUSINESS AND PROPERTIES

Summary

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in North America and the United Kingdom. As used in this report, the terms Murphy, Murphy Oil, we, our, its and Company may refer to Murphy Oil Corporation or any one or more of its consolidated subsidiaries.

The Company was originally incorporated in Louisiana in 1950 as Murphy Corporation. It was reincorporated in Delaware in 1964, at which time it adopted the name Murphy Oil Corporation, and was reorganized in 1983 to operate primarily as a holding company of its various businesses. Its operations are classified into two business activities: (1) “Exploration and Production” and (2) “Refining and Marketing.” For reporting purposes, Murphy’s exploration and production activities are subdivided into six geographic segments, including the United States, Canada, the United Kingdom, Ecuador, Malaysia and all other countries. Murphy’s refining and marketing activities are presently subdivided into geographic segments for North America and United Kingdom. Additionally, “Corporate and Other Activities” include interest income, interest expense and overhead not allocated to the segments.

The information appearing in the 2003 Annual Report to Security Holders (2003 Annual Report) is incorporated in this Form 10-K report as Exhibit 13 and is deemed to be filed as part of this Form 10-K report as indicated under Items 1, 2 and 7. A narrative of the graphic and image information that appears in the paper format version of Exhibit 13 is included in the electronic Form 10-K document as an appendix to Exhibit 13.

In addition to the following information about each business activity, data about Murphy’s operations, properties and business segments, including revenues by class of products and financial information by geographic area, are provided on pages 11 through 20, F-13, F-31 through F-33, F-37 through F-39, and F-41 of this Form 10-K report and on pages 5 through 13 of the 2003 Annual Report.

Interested parties may access the Company’s public disclosures filed with the Securities and Exchange Commission, including Form 10-K, Form 10-Q, Form 8-K and other documents, by accessing the Investor Relations section of Murphy Oil Corporation’s website at www.murphyoilcorp.com.

Exploration and Production

The Company’s exploration and production business explores for and produces crude oil, natural gas and natural gas liquids worldwide.

During 2003, Murphy’s principal exploration and production activities were conducted in the United States by wholly owned Murphy Exploration & Production Company-USA (Murphy Expro USA), and in Ecuador and Malaysia by wholly owned Murphy Exploration & Production Company-International (Murphy Expro International) and its subsidiaries, in western Canada and offshore eastern Canada by wholly owned Murphy Oil Company Ltd. (MOCL) and its subsidiaries, and in the U.K. North Sea and the Atlantic Margin by wholly owned Murphy Petroleum Limited. Murphy’s crude oil and natural gas liquids production in 2003 was in the United States, Canada, the United Kingdom, Malaysia and Ecuador; its natural gas was produced and sold in the United States, Canada and the United Kingdom. MOCL owns a 5% undivided interest in Syncrude Canada Ltd. in Northern Alberta, the world’s largest producer of synthetic crude oil.

Murphy’s worldwide crude oil, condensate and natural gas liquids production in 2003 averaged 83,452 barrels per day, an increase of 9% compared to 2002. The increase was primarily due to the start-up of the West Patricia field in Block SK 309, offshore Sarawak, Malaysia. The Company’s worldwide sales volume of natural gas averaged 215 million cubic feet per day in 2003, down 27% from 2002 levels. The main reason for the lower natural gas sales was a decline in production at the Ladyfern field in British Columbia, Canada. Natural gas sales were also lower in the U.S. in 2003 due to normal decline in Gulf of Mexico field production.

Total crude oil, condensate and natural gas liquids production is expected to increase in 2004 because of a full year of production at the West Patricia field offshore Malaysia and two deepwater Gulf of Mexico fields known as Medusa and Habanero. West Patricia started up in May 2003, while Medusa and Habanero came on line in November 2003. The Company anticipates first production from another deepwater Gulf of Mexico field named Front Runner in the second

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half of 2004. The Company announced in late 2003 that it intends to sell most of its conventional oil and gas properties in the Western Canadian Sedimentary Basin (WCSB). This sale will reduce 2004 production by about 20,000 net barrels of oil equivalent per day. Natural gas sales volumes are expected to decline in 2004 compared to 2003 as the higher production from the three deepwater Gulf of Mexico fields mentioned above will not offset the effect of the sale of Western Canada properties and normal production declines in other areas.

In the United States, Murphy has production of oil and/or natural gas from 16 fields operated by the Company and 16 fields operated by others. Of the total producing fields at December 31, 2003, two are in the deepwater Gulf of Mexico, 24 are in more shallow waters on the Gulf of Mexico continental shelf, five are onshore in Louisiana, and one is the Northstar field in Alaska. The Company’s primary focus in the U.S. is in the deepwater Gulf of Mexico, which is generally defined as water depths of 1,000 feet or more. During the fourth quarter of 2003, the Company’s first two deepwater fields came on production. The Company operates and owns a 60% interest in the Medusa field, in Mississippi Canyon Blocks 538/582. Peak net production from Medusa is expected to be 25,000 barrels of oil equivalent per day. The Company owns a 33.75% interest in the Habanero field in Garden Banks Block 341. Habanero, which is operated by Shell, should reach peak net production of 7,000 barrels of oil equivalent per day in 2004. Murphy has another deepwater discovery at the Front Runner field in Green Canyon Blocks 338/339 which is in development and should come on stream in the second half of 2004. Murphy owns 37.5% and operates the Front Runner field, which is expected to have peak net production of 20,000 barrels of oil equivalent per day. Murphy holds an interest in 173 blocks in the deepwater Gulf of Mexico, and expects to drill about four deepwater prospects per year over the next several years. The Company’s two largest producing areas on the continental shelf of the Gulf of Mexico are the Tahoe field at Viosca Knoll Block 783 (30%) and South Timbalier Blocks 63/86 (100%/96%). Tahoe is operated by Shell and produced about 19 million cubic feet (MMCF) of natural gas per day and 500 barrels of oil per day net to the Company in 2003. Murphy operates South Timbalier Blocks 63/86 with a combined net production of about 1,000 barrels of oil per day and 13 MMCF per day in 2003. Onshore production, which is mostly natural gas, is primarily located on several leases in Vermilion Parish, Louisiana. Murphy’s net production in 2003 from onshore fields was 30 MMCF per day. The Company owns approximately a 1.4% working interest in the Northstar field operated by BP in Alaska. Total net oil production for this field was approximately 700 barrels per day in 2003.

In Canada, the Company owns an interest in three legacy assets, the Hibernia and Terra Nova fields offshore Newfoundland and Syncrude Canada Ltd. In addition, the Company owned interests in several fields in the WCSB at the end of 2003. In December 2003, the Company announced its intent to sell most of these WCSB assets, while retaining a limited number of heavy oil and natural gas fields which are strategic to the Company. Assets to be sold produced about 20,000 barrels of oil equivalent per day in 2003 and had total proved reserves of approximately 46 million barrels of oil equivalent at the end of the year. The marketing of these assets has commenced in early 2004, with an anticipated sale in the second quarter. Murphy holds a 6.5% interest in Hibernia and a 12% interest in Terra Nova, with these being the first two fields on production in the Jeanne d’Arc Basin, offshore Newfoundland. Total net production in 2003 was 12,800 barrels of oil per day from Hibernia, which is operated by Hibernia Management and Development Company, while net production from Terra Nova, which is operated by PetroCanada, was 15,700 barrels of oil per day. Murphy owns a 5% undivided interest in Syncrude Canada Ltd., a joint venture located about 25 miles north of Fort McMurray, Alberta. Syncrude utilizes its assets to extract bitumen from oil sand deposits and to upgrade this bitumen into a high-value synthetic crude oil. Syncrude is currently expanding its facilities and is adding a third coker that will allow for increased production beginning in 2006. Total net production in 2003 was 10,500 barrels of crude oil per day, but should increase in 2004 due to improvements in operational efficiency. Although Syncrude produces a very high quality synthetic crude oil from bitumen, the U.S. Securities and Exchange Commission (SEC) does not allow the Company to include Syncrude’s reserves in its proved oil reserves, which are reported on page F-35. The SEC considers Syncrude to be a mining operation, and not a conventional oil operation. Murphy and its partners have made a potential natural gas discovery at the Annapolis field, offshore Nova Scotia. An appraisal well is expected to be drilled in 2004 to determine whether this discovery has commercial size. Annapolis is operated by Marathon, and Murphy is a 19% owner in the block.

Murphy produces oil and natural gas in the United Kingdom sector of the North Sea. In 2003 the Company sold its interest in the Ninian and Columba fields. Production from these two fields averaged about 4,400 barrels per day in 2003 prior to the sale. The Company’s primary oil production in the U.K. is now derived from two areas, Schiehallion and Mungo/Monan. Murphy owns 5.88% of the Schiehallion field operated by BP. This field is located in an area known as the Atlantic Margin and lies west of the Shetland Islands. Schiehallion produces oil into a Floating Production Storage and Offloading vessel (FPSO). The oil is transported via dedicated tanker to Sullom Voe terminal, where the oil is sold to third parties. Schiehallion produced approximately 5,700 net barrels of oil per day in 2003. Schiehallion development will continue with further infield drilling planned in 2005 onwards. Mungo/Monan is also operated by BP and is 12.65% owned by Murphy. The Mungo field produces through an unmanned platform, while Monan is produced through subsea

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facilities. Both the platform and subsea facilities are tied to a central processing facility that is linked to the Forties pipeline system. In 2003, the Mungo and Monan fields produced approximately 5,000 barrels of oil per day, net to Murphy’s interest.

In Ecuador, Murphy owns a 20% working interest in Block 16, which is operated by Repsol YPF under a participation contract. In the second half of 2003, the start-up of the OCP pipeline, owned by other companies, enabled higher production from Block 16. However, inadequate water handling facilities combined with other operational issues have led to less than planned production from this field. Block 16 owners are evaluating alternatives for maximizing field production. The Company’s net production was 5,200 barrels of oil per day in 2003; but exiting the year production totaled about 8,000 net barrels per day from the field. Due to utilization of the last foreign exchange loss carryforwards in the 2003 tax return, the Company expects to incur its first significant income tax liability in Ecuador beginning in 2004.

The Company has majority interests in eight separate production sharing contracts (PSCs) in Malaysia. The Company serves as the operator of all these areas, which cover approximately 14.4 million acres in total. Murphy has an 85% interest in two shallow water blocks, known as SK 309 and SK 311. The West Patricia field in Block SK 309, discovered in 2002, came on stream in May 2003. The Company’s net share of production averaged about 10,700 barrels of oil per day in the fourth quarter of 2003. The Company made a major discovery at the Kikeh field in deepwater Block K in 2002 and added a discovery at Kikeh Kecil in 2003. Further exploration and appraisal drilling will occur in the 80% owned Block K in 2004. A development plan is in progress for the Kikeh field, and the Company expects that its Board of Directors and Malaysian authorities will approve the development plan in 2004. First production at Kikeh is currently expected in 2007. The Company drilled its first exploration well in its 80% owned Block H in 2003, but the well was unsuccessful. Murphy also owns 75% interests in Blocks PM 311 and PM 312, located offshore peninsular Malaysia. Murphy plans to commence its first exploration drilling on the peninsular Malaysia blocks in 2004. The Company was awarded interests in PSCs covering deepwater Blocks L (60%) and M (70%) in early 2003. Murphy drilled a wildcat well in Block L in mid-2003. Well results have been kept confidential and well costs held in suspension. A total of 2.9 million gross acres associated with Blocks L and M have been included in the acreage table on page 4.

The Company signed Production Sharing Agreements (PSAs) covering two offshore blocks in the Republic of Congo in 2003. The Company has an 85% interest in each PSA. These blocks cover approximately 1.8 million acres with water depths ranging from 490 to 6,900 feet. These blocks are named Mer Profonde Sud and Mer Profonde Nord. Murphy plans to drill its first exploration well on these blocks in 2004. Murphy has not included these net acres in its acreage table on page 4 pending the completion of statutory procedures required for final award of the acreage, which is expected to occur in 2004.

Murphy’s estimated net quantities of proved oil and gas reserves and proved developed oil and gas reserves at December 31, 2000, 2001, 2002 and 2003 by geographic area are reported on pages F-35 and F-36 of this Form 10-K report. Murphy has not filed and is not required to file any estimates of its total net proved oil or gas reserves on a recurring basis with any federal or foreign governmental regulatory authority or agency other than the U.S. Securities and Exchange Commission. Annually, Murphy reports gross reserves of properties operated in the United States to the U.S. Department of Energy; such reserves are derived from the same data from which estimated net proved reserves of such properties are determined.

Net crude oil, condensate, and gas liquids production and sales, and net natural gas sales by geographic area with weighted average sales prices for each of the five years ended December 31, 2003 are shown on page 8 of the 2003 Annual Report.

Production expenses for the last three years in U.S. dollars per equivalent barrel are discussed on pages 15 and 16 of this Form 10-K report. For purposes of these computations, natural gas sales volumes are converted to equivalent barrels of crude oil using a ratio of six thousand cubic feet (MCF) of natural gas to one barrel of crude oil.

Supplemental disclosures relating to oil and gas producing activities are reported on pages F-34 through F-41 of this Form 10-K report.

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At December 31, 2003, Murphy held leases, concessions, contracts or permits on developed and undeveloped acreage as shown by geographic area in the following table. Gross acres are those in which all or part of the working interest is owned by Murphy. Net acres are the portions of the gross acres applicable to Murphy’s working interest.

The only significant undeveloped acreage that expires in the next three years is approximately 4.2 million acres in Block K in Malaysia that is not included in the Kikeh discovery area. The Company is currently negotiating to extend the exploration rights for this acreage.

As used in the three tables that follow, “gross” wells are the total wells in which all or part of the working interest is owned by Murphy, and “net” wells are the total of the Company’s fractional working interests in gross wells expressed as the equivalent number of wholly owned wells.

The following table shows the number of oil and gas wells producing or capable of producing at December 31, 2003.

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Murphy’s net wells drilled in the last three years are shown in the following table.

Murphy’s drilling wells in progress at December 31, 2003 are shown below.

Additional information about current exploration and production activities is reported on pages 6 through 10 of the 2003 Annual Report.

Refining and Marketing

The Company’s refining and marketing businesses are located in North America and the United Kingdom, and primarily consist of operations that refine crude oil and other feedstocks into petroleum products such as gasoline and distillates, buy and sell crude oil and refined products, and transport and market petroleum products.

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Murphy Oil USA, Inc. (MOUSA), a wholly owned subsidiary of Murphy Oil Corporation, owns and operates two refineries in the United States. The Meraux, Louisiana refinery is located on fee land and on two leases that expire in 2010 and 2021, at which times the Company has options to purchase the leased acreage at fixed prices. The refinery at Superior, Wisconsin is located on fee land. Murco Petroleum Limited (Murco), a wholly owned U.K. subsidiary serviced by Murphy Eastern Oil Company, has an effective 30% interest in a refinery at Milford Haven, Wales that can process 108,000 barrels of crude oil per day. Refinery capacities at December 31, 2003 are shown in the following table.

The Company completed its expansion of the Meraux refinery in the fourth quarter 2003. The expansion allows the refinery to meet new low-sulfur gasoline specifications which become effective for the Company in 2008. The expansion included a new hydrocracker unit, central control room and two new utility boilers; expansion of the crude oil processing capacity to 125,000 barrels per stream day (b/sd); expansion of naphtha hydrotreating capacity to 35,000 b/sd; expansion of the catalytic reforming capacity to 32,000 b/sd; and construction of a new sulfur recovery complex, including amine regeneration, sour water stripping and high efficiency sulfur recovery. The Meraux plant has no solvent deasphalting processing capability at December 31, 2003 because of the fire in June 2003 that destroyed the Residual Oil Supercritical Extractor (ROSE) unit. The unit is being rebuilt, primarily using proceeds of property insurance, and should be operational in the fourth quarter 2004. While the ROSE unit is being rebuilt, the refinery will produce a larger volume of heavy fuel oil. The Company is in the process of building an FCC gasoline hydrotreater unit at its Superior, Wisconsin refinery, that is expected to be completed in late 2004. This unit will allow Superior to meet low-sulfur gasoline specifications.

MOUSA markets refined products through a network of retail gasoline stations and branded and unbranded wholesale customers in a 23-state area of the southern and midwestern United States. Murphy’s retail stations are primarily located in the parking areas of Wal-Mart stores in 21 states and use the brand name Murphy USA^®. Branded wholesale customers use the brand name SPUR^®. Refined products are supplied from 12 terminals that are wholly owned and operated by MOUSA and numerous terminals owned by others. Of the wholly owned terminals, four are supplied by marine transportation, three are supplied by truck, two are adjacent to MOUSA’s refineries and three are supplied by pipeline. MOUSA receives products at the terminals owned by others either in exchange for deliveries from the Company’s terminals or by outright purchase. The Company sold its jointly owned terminals in early 2004. At December 31, 2003, the Company marketed products through 623 Murphy USA stations and 363 branded wholesale SPUR stations. MOUSA plans to add about 160 new Murphy USA stations at Wal-Mart sites in the southern and midwestern United States in 2004. In 2002, the Company and Wal-Mart reached an agreement for a Canadian subsidiary of the Company to market products through Murphy Canada^TM stations at select Wal-Mart stores across Canada. The Company’s subsidiary operates eight stations at Wal-Mart sites in Canada at December 31, 2003.

Murphy has master agreements that allow the Company to rent space in the parking lots of Wal-Mart stores in 21 states and in Canada for the purpose of building retail gasoline stations. The master agreements contain general terms applicable to all sites in the United States and Canada. As each individual station is constructed, an addendum to the master agreement is entered into, which contains the terms specific to that location. The terms of the agreements range from 10-15 years at each station, with Murphy holding two successive five-year extension options at each site. The agreements permit Wal-Mart to terminate the agreements in their entirety, or only as to affected sites, at its option for the following reasons: Murphy vacates or abandons the property; Murphy improperly transfers the rights under this agreement to

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another party; an agreement or a premises is taken upon execution or by process of law; Murphy files a petition in bankruptcy or becomes insolvent; Murphy fails to pay its debts as they become due; Murphy fails to pay rent or other sums required to be paid within 90 days after written notice; or Murphy fails to perform in any material way as required by the agreements. Sales from these stations amounted to 35.8% of total Company revenues in 2003, 30.3% in 2002 and 22.5% in 2001. As the Company continues to expand the number of gasoline stations at Wal-Mart sites, total revenue generated by this business is expected to grow proportionately.

At the end of 2003, Murco distributed refined products in the United Kingdom from the Milford Haven refinery, three wholly owned terminals supplied by rail, six terminals owned by others where products are received in exchange for deliveries from the Company’s terminals, and 384 branded stations under the brand names MURCO and EP.

Murphy owns a 20% interest in a 120-mile refined products pipeline, with a capacity of 165,000 barrels a day, that transports products from the Meraux refinery to two common carrier pipelines serving the southeastern United States. The Company also owns a 3.2% interest in LOOP LLC, which provides deepwater unloading accommodations off the Louisiana coast for oil tankers and onshore facilities for storage of crude oil. A crude oil pipeline with a diameter of 24 inches connects LOOP storage at Clovelly, Louisiana to the Meraux refinery. Murphy owns 29.4% of the first 22 miles of this pipeline from Clovelly to Alliance, Louisiana and 100% of the remaining 24 miles from Alliance to Meraux. The pipeline is connected to another company’s pipeline system, allowing crude oil transported by that system to also be shipped to the Meraux refinery. In February 2002, the Company sold its 22% interest in a 312-mile crude oil pipeline in Montana and Wyoming for $7 million.

In May 2001, the Company sold its Canadian pipeline and trucking operation, including seven crude oil pipelines with various ownership percentages and capacities. Murphy realized an after-tax gain of $71 million on this sale.

Additional information about current refining and marketing activities and a statistical summary of key operating and financial indicators for each of the five years ended December 31, 2003 are reported on pages 11 through 13 of the 2003 Annual Report.

Employees

At December 31, 2003, Murphy had 4,789 employees – 2,103 full-time and 2,686 part-time.

Competition and Other Conditions Which May Affect Business

Murphy operates in the oil industry and experiences intense competition from other oil companies, which include state-owned foreign oil companies, major integrated oil companies, independent producers of oil and natural gas and independent refining companies. Virtually all of the state-owned and major integrated oil companies and many of the independent producers and independent refiners that compete with the Company have substantially greater resources than Murphy. In addition, the oil industry as a whole competes with other industries in supplying energy requirements around the world. Murphy is a net purchaser of crude oil and other refinery feedstocks, and also purchases refined products, particularly gasoline needed to supply its retail marketing stations located at Wal-Mart sites. The Company may be required to respond to operating and pricing policies of others, including producing country governments from whom it makes purchases. Additional information concerning current conditions of the Company’s business is reported under the caption “Outlook” beginning on page 25 of this Form 10-K report.

In 2003, the Company’s production of oil and natural gas represented approximately .1% of the respective worldwide totals. Murphy owned approximately 1% of the crude oil refining capacity in the United States and its market share of U.S. retail gasoline sales was slightly above 1%.

The operations and earnings of Murphy have been and continue to be affected by worldwide political developments. Many governments, including those that are members of the Organization of Petroleum Exporting Countries (OPEC), unilaterally intervene at times in the orderly market of crude oil and natural gas produced in their countries through such actions as setting prices, determining rates of production, and controlling who may buy and sell the production.

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In addition, prices and availability of crude oil, natural gas and refined products could be influenced by political unrest and by various governmental policies to restrict or increase petroleum usage and supply. Other governmental actions that could affect Murphy’s operations and earnings include tax changes and regulations concerning: currency fluctuations, protection and remediation of the environment (See the caption “Environmental” beginning on page 20 of this Form 10-K report), preferential and discriminatory awarding of oil and gas leases, restrictions on drilling and/or production, restraints and controls on imports and exports, safety, and relationships between employers and employees. Because these and other factors too numerous to list are subject to constant changes caused by governmental and political considerations and are often made in great haste in response to changing internal and worldwide economic conditions and to actions of other governments or specific events, it is not practical to attempt to predict the effects of such factors on Murphy’s future operations and earnings.

Murphy’s business is subject to operational hazards and risks normally associated with the exploration for and production of oil and natural gas and the refining and marketing of crude oil and petroleum products. The occurrence of an event, including but not limited to acts of nature, mechanical equipment failures, industrial accidents, fires and intentional attacks could result in the loss of hydrocarbons and associated revenues, environmental pollution or contamination, and personal injury or bodily injury, including death, for which the Company could be deemed to be liable, and could subject the Company to substantial fines and/or claims for punitive damages. Murphy maintains insurance against certain, but not all, hazards that could arise from its operations, and such insurance is believed to be reasonable for the hazards and risks faced by the Company. As of December 31, 2003, the Company maintained total excess liability insurance with limits of $500 million per occurrence covering employees, general liability and certain “sudden and accidental” environmental risks. The Company also maintained insurance coverage with an additional limit of $250 million per occurrence, all or part of which could be applicable to certain gradual and/or sudden and accidental pollution events. There can be no assurance that such insurance will be adequate to offset lost revenues or costs associated with certain events or that insurance coverage will continue to be available in the future on terms that justify its purchase. The occurrence of an event that is not fully insured could have a material adverse effect on the Company’s financial condition and results of operations in the future.

Executive Officers of the Registrant

The age at January 1, 2004, present corporate office and length of service in office of each of the Company’s executive officers are reported in the following listing. Executive officers are elected annually but may be removed from office at any time by the Board of Directors.

Claiborne P. Deming – Age 49; President and Chief Executive Officer since October 1994 and Director and Member of the Executive Committee since 1993. He served as Executive Vice President and Chief Operating Officer from 1992 to 1993 and President of MOUSA from 1989 to 1992.

Steven A. Cossé – Age 56; Senior Vice President since October 1994 and General Counsel since August 1991. Mr. Cossé was elected Vice President in 1993. For the eight years prior to August 1991, he was General Counsel for Ocean Drilling & Exploration Company (ODECO), a majority-owned subsidiary of Murphy.

W. Michael Hulse – Age 50; Executive Vice President – Worldwide Downstream Operations effective April 2003. Mr. Hulse has been President of MOUSA from November 2001 to present. He served as President of Murphy Eastern Oil Company from April 1996 to November 2001.

Bill H. Stobaugh – Age 52; Vice President since May 1995, when he joined the Company. Prior to that, he had held various engineering, planning and managerial positions, the most recent being with an engineering consulting firm.

Kevin G. Fitzgerald – Age 48; Treasurer since July 2001. Mr. Fitzgerald was Director of Investor Relations from 1996 to June 2001, and also served in various capacities with the Company and ODECO between 1982 and 1996.

John W. Eckart – Age 45; Controller since March 2000. Mr. Eckart had been Assistant Controller since February 1995 after joining the Company as Auditing Manager in 1990.

Walter K. Compton – Age 41; Secretary since December 1996. He became Manager, Law Department, in November 1996, and has been an attorney with the Company since 1988.

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Item 3. LEGAL PROCEEDINGS

In December 2000, two of the Company’s Canadian subsidiaries, Murphy Oil Company Ltd. (MOCL) and Murphy Canada Exploration Company (MCEC), as plaintiffs filed an action in the Court of Queen’s Bench of Alberta seeking a constructive trust over oil and gas leasehold rights to Crown lands in British Columbia. The suit alleges that the defendants, The Predator Corporation Ltd. and Predator Energies Partnership (collectively Predator) and Ricks Nova Scotia Co. (Ricks), acquired the lands after first inappropriately obtaining confidential and proprietary data belonging to the Company and its partner. In January 2001, Ricks, representing an undivided 75% interest in the lands in question, settled its portion of the litigation by conveying its interest to the Company and its partner at cost. In 2001, Predator, representing the remaining undivided 25% of the lands in question, filed a counterclaim, as subsequently amended, against MOCL and MCEC and MOCL’s President individually seeking compensatory damages of C$3.61 billion. The Company believes that the counterclaim is without merit and that the amount of damages sought is frivolous. Trial will likely begin in January 2005. While the litigation is in the discovery stage and no assurance can be given about the outcome, the Company does not believe that the ultimate resolution of this suit will have a material adverse effect on its financial condition.

On June 10, 2003, a fire severely damaged the Residual Oil Supercritical Extraction (ROSE) unit at the Company’s Meraux, Louisiana refinery. The ROSE unit recovers feedstock from the heavy fuel oil stream for conversion into gasoline and diesel. Subsequent to the fire, 17 class action lawsuits have been filed seeking damages for area residents. All the lawsuits have been administratively consolidated into a single legal action. The Company maintains liability insurance that covers such matters, and it recorded the applicable insurance deductible as an expense in 2003. Accordingly, the Company does not believe that the ultimate resolution of the class action litigation will have a material adverse effect on its financial condition.

On March 5, 2002, two of the Company’s subsidiaries filed suit against Enron Canada Corp. (Enron) to collect approximately $2.1 million owed to Murphy under canceled gas sales contracts. On May 1, 2002, Enron counterclaimed for approximately $19.8 million allegedly owed by Murphy under those same agreements. Although the lawsuit in the Court of Queen’s Bench, Alberta, is in its early stages and no assurance can be given, the Company does not believe that the Enron counterclaim is meritorious and does not believe that the ultimate resolution of this matter will have a material adverse effect on its financial condition.

Murphy and its subsidiaries are engaged in a number of other legal proceedings, all of which Murphy considers routine and incidental to its business and none of which is expected to have a material adverse effect on the Company’s financial condition. Based on information currently available to the Company, the ultimate resolution of matters referred to in this item is not expected to have a material adverse effect on the Company’s earnings or financial condition in a future period.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders during the fourth quarter of 2003.

PART II

Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

The Company’s Common Stock is traded on the New York Stock Exchange using “MUR” as the trading symbol. There were 2,839 stockholders of record as of December 31, 2003. Information as to high and low market prices per share and dividends per share by quarter for 2003 and 2002 are reported on page F-42 of this Form 10-K report.

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Item 6. SELECTED FINANCIAL DATA

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Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

Murphy Oil Corporation is a worldwide oil and gas exploration and production company with refining and marketing operations in North America and the United Kingdom. A more detailed description of the Company’s significant assets can be found in Items 1 and 2 of this Form 10-K report.

Murphy generates revenue primarily by selling its oil and natural gas production and its refined petroleum products to third parties at hundreds of locations in the United States, Canada and other countries. The Company’s revenue is highly affected by the prices of oil, natural gas and refined petroleum products it sells. Also, because crude oil is purchased by the Company for refinery feedstocks, natural gas is purchased for fuel at its refineries and oil fields, and gasoline is purchased to supply its retail gasoline stations in North America that are primarily located at Wal-Mart stores, the purchase prices for these commodities also have a significant effect on the Company’s costs. In order to make a profit and generate cash in its exploration and production business, revenue generated from the sales of oil and natural gas produced must exceed the combined costs of producing these products, amortization of capital expenditures and expenses related to exploration. Profits and generation of cash in the Company’s downstream operations are dependent upon achieving an adequate margin, which is determined by the sales prices for refined petroleum products less the costs of refinery feedstocks and gasoline purchases and expenses associated with manufacturing, transporting and marketing these products. Murphy also incurs certain costs for general company administration and for capital borrowed from lending institutions.

In general, worldwide oil prices and North American natural gas prices were stronger in 2003 than in 2002. The average price for West Texas Intermediate crude oil in 2003 was $31.00, an increase of 18% compared to 2002. The NYMEX natural gas price averaged $5.49 in 2003, up 63% over 2002. These price improvements were a significant factor leading to higher profits in the Company’s exploration and production business in 2003 compared to the prior year. The Company did not fully benefit from the higher prices in 2003, because approximately 30% of its 2003 oil and natural gas production was hedged at prices that were lower than actual market prices in 2003. In addition, the higher prices for crude oil were a contributing factor to low refining and marketing margins in North America during a portion of 2003. If the prices for crude oil and natural gas decline significantly in 2004 or beyond, the Company would expect this to have an unfavorable impact on operating profits for its exploration and production business. Such lower oil and gas prices could, but may not, have a favorable impact on the Company’s refining and marketing operating profits.

Results of Operations

The Company reported net income in 2003 of $294.2 million, $3.17 per diluted share, compared to net income in 2002 of $111.5 million, $1.21 per diluted share. In 2001 the Company earned $330.9 million, $3.63 per diluted share. The higher net income in 2003 compared to 2002 was caused by a combination of better earnings in the Company’s exploration and production operations, a lower loss in refining and marketing operations, and lower net costs for corporate functions. The income reduction in 2002 compared to 2001 was due to lower earnings in the exploration and production business, significantly lower earnings in the refining and marketing area, and higher net costs for corporate functions. Further explanations of each of these variances are found in the following sections.

On January 1, 2003, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, which requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. Upon adoption of SFAS No. 143, the Company recorded an expense of $7 million, net of $1.4 million in income taxes, as the cumulative effect of a change in accounting principle. Further explanation of this accounting change is included in Note B to the consolidated financial statements. Income before the cumulative effect of a change in accounting principle was $301.2 million ($3.25 per share) in 2003, $111.5 million ($1.21 per share) in 2002, and $330.9 million ($3.63 per share) in 2001.

In December 2002 the Company sold its interest in Ship Shoal Block 113 in the Gulf of Mexico. The results of operations for Ship Shoal Block 113 have been reflected as discontinued operations in 2002 and 2001 in accordance with Statement of Financial Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Therefore, the gain on disposal of $10.6 million in 2002 and other operating results of the field have been included net of income tax expense as Discontinued Operations in the consolidated statements of income for the years ended December 31, 2002 and 2001. Income from continuing operations was $301.2 million ($3.25 per share) in 2003, $97.5 million ($1.06 per share) in 2002, and $328.4 million ($3.60 per share) in 2001.

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2003 vs. 2002 – Net income in 2003 was $294.2 million, $3.17 per diluted share, compared to $111.5 million, $1.21 per diluted share, in 2002. The 2003 period included an after-tax expense of $7 million, $.08 per share, related to a cumulative effect of a change in accounting principle associated with adoption of SFAS No. 143, Accounting for Asset Retirement Obligations. The 2002 period included profit on discontinued operations of $14 million, $.15 per share. Excluding the accounting change in 2003 and the results of discontinued operations in 2002, income from continuing operations was $301.2 million, $3.25 per share, in 2003, and $97.5 million, $1.06 per share, in 2002. The $203.7 million higher income from continuing operations in 2003 compared to 2002 was attributable to $165.2 million higher earnings from exploration and production operations, a $28.7 million lower loss from refining and marketing operations and a $9.8 million lower net cost of corporate activities. Earnings from exploration and production operations were up in 2003 primarily due to higher oil and natural gas sales prices, a $34 million after-tax gain on sale of the Ninian and Columba fields in the U.K. North Sea, record levels of oil production, higher tax benefits from settlement and rate adjustments, and lower property impairment and exploration expenses. Sales of natural gas were down significantly in 2003 primarily due to lower gas production in Canada. Refining and marketing results in both North America and the United Kingdom showed significant improvements in 2003. Most of the improvement in North America was generated by stronger margins in the retail marketing portion of the business. Higher margins in the U.K. led to better income from this area. The net costs of corporate activities were lower in 2003 primarily due to higher corporate income tax benefits related to settlement of prior year tax matters and lower net interest costs, partially offset by higher selling and general expenses.

Sales and other operating revenues in 2003 increased by $1.3 billion compared to 2002 due to higher sales volumes for crude oil and refined petroleum products, higher sales prices for oil, natural gas and refined products, and higher merchandise sales at retail gasoline stations. Gain on sale of assets was $52.4 million higher in 2003 primarily due to a $50 million pretax profit on sale of the Ninian and Columba fields in the U.K. North Sea. Crude oil, natural gas and product purchases expense increased by $975.9 million in 2003 due to higher costs of crude oil used for refinery feedstock, and higher costs and volumes of gasoline and merchandise purchased for sale at the Company’s retail gasoline stations. Operating expenses increased by $86.7 million in 2003 due to higher operating and repair costs at refineries and higher operating costs at the Company’s growing retail gasoline station chain. Selling and general expenses rose by $28 million in 2003 primarily due to higher retirement and incentive compensation expenses and higher costs for Malaysian operations. Exploration expenses were $8.3 million lower in 2003 mostly due to less exploratory costs incurred in Malaysia. Depreciation, depletion and amortization expense increased by $28.5 million in 2003 due to new production from the West Patricia field, offshore Sarawak Malaysia, and higher depreciation associated with the Company’s growing retail gasoline station chain. Impairment of long-lived assets was $23.3 million lower in 2003 as the prior year included costs related to write-off of Destin Dome Blocks 56 and 57, offshore Florida. The 2003 statement of income included $12.4 million for accretion on discounted abandonment liabilities following the adoption of SFAS No. 143 on January 1, 2003. Because the abandonment liabilities are carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the time the abandonment occurs. Interest expense rose by $6.2 million in 2003 due to higher average borrowings under long-term debt during the year. The portion of interest capitalized increased by $12.7 million due to higher capital expenditures for development of deepwater Gulf of Mexico fields and expansion projects at Syncrude and the Meraux refinery. Income tax expense was $63.8 million more in 2003 mostly caused by higher pretax earnings, the effects of which were partially offset by a $20.1 million benefit from settlement of prior year tax audits in the U.S., an $11.8 million benefit related to enacted tax rate reductions in Canada, and an $11.4 million credit from recognition of deferred tax benefits in Malaysia.

2002 vs. 2001 – Income from continuing operations in 2002 was $97.5 million, $1.06 per share, compared to $328.4 million, $3.60 per share, in 2001. Lower income in 2002 of $230.9 million was mainly due to a $193.6 million reduction in refining and marketing results, caused by both weaker refining margins in 2002 compared to 2001 in the U.S. and U.K., and a $71 million gain in 2001 from sale of Canadian pipeline and trucking operations. Earnings from the Company’s exploration and production activities were $26.5 million lower in 2002 than in 2001 as higher oil production, record levels of natural gas production and higher average oil sales prices were more than offset by lower natural gas sales prices, higher charges for property impairments and higher production and depreciation expenses.

Sales and other operating revenues were $222.5 million higher in 2002 than in 2001 due to higher crude oil production, record sales of natural gas, and higher sales volumes for refined products in North America and the United Kingdom. Gain on sale of assets declined by $96.4 million primarily due to the sale of Canadian pipeline and trucking assets in 2001. Interest and other income was $7.8 million lower in 2002 due to less interest earned on invested cash. Crude oil, natural gas and product purchases expense increased by $305.5 million in 2002 due to more purchases of finished

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products for retail marketing operations and a higher average purchase price for these products than in 2001. Operating expenses rose by $60.7 million mainly due to higher oil and natural gas production, higher maintenance costs for oil and gas producing fields and $5 million of costs to repair uninsured damage from tropical storms in the Gulf of Mexico. Depreciation, depletion and amortization expense increased $73.4 million in 2002 due to higher oil and natural gas production and more retail gasoline stations. Interest expense was $12.2 million more in 2002 due to higher average long-term borrowings than in 2001, including the sale of 10-year notes with a stated rate of 6.375% in 2002. Capitalized interest increased by $4.3 million due to ongoing projects to develop deepwater Gulf of Mexico fields, expand Syncrude, and build a hydrocracker and expand crude oil throughput capacity at the Meraux refinery. Income tax expense fell by $119.5 million essentially in line with lower pretax income from continuing operations.

In the following table, the Company’s results of operations for the three years ended December 31, 2003 are presented by segment. More detailed reviews of operating results for the Company’s exploration and production and refining and marketing activities follow the table.

Exploration and Production – Earnings from exploration and production operations were $326.2 million in 2003, $161 million in 2002 and $187.5 million in 2001. The improvement in earnings in 2003 was primarily caused by a 7% higher realized worldwide oil sales price, a 64% higher realized natural gas sales price in North America, record crude oil production that was 9% higher than in 2002, a $34 million after-tax gain on sale of the Ninian and Columba fields in the U.K. North Sea, higher tax benefits from settlements and rate adjustments, and lower expenses related to property impairments and exploration. Natural gas sales volumes were 27% lower in 2003, primarily due to a decline in production at the Ladyfern field in Canada. Higher oil production was mostly attributable to start up in May 2003 of the West Patricia field, offshore Sarawak Malaysia. The reduction in property impairment expense in 2003 was primarily related to the write-off of the remaining costs for Destin Dome Blocks 56 and 57, offshore Florida, in 2002. The decline in exploration expenses was mostly attributable to lower exploratory costs in Malaysia.

Lower earnings in 2002 compared to 2001 was caused by a 24% lower average natural gas sales price in North America, higher costs associated with property impairments and higher production and depreciation expenses. The unfavorable effects of these items were partially offset by higher production of crude oil, record levels of natural gas sales, and a 10% higher average sales price for crude oil and condensate. Oil production from continuing operations increased by 13% in 2002 and natural gas production from continuing operations rose by 5%. Higher property impairment expense in 2002 was mostly related to the write-off of remaining costs for Destin Dome Blocks 56 and 57, offshore Florida.

The results of operations for oil and gas producing activities for each of the last three years are shown by major operating areas on pages F-38 and F-39 of this Form 10-K report. Daily production and sales rates and weighted average sales prices are shown on page 8 of the 2003 Annual Report.

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A summary of oil and gas revenues from continuing operations, including intersegment sales that are eliminated in the consolidated financial statements, is presented in the following table.

The Company’s crude oil, condensate and natural gas liquids production from continuing operations averaged 83,452 barrels per day in 2003, 75,213 barrels in 2002 and 66,344 barrels in 2001. Oil production in 2003 was a new annual record for Murphy Oil. Oil production from continuing operations in the United States increased 10% to 4,526 barrels per day. Production from two new deepwater Gulf of Mexico fields – Medusa and Habanero – that came on stream in November 2003 more than offset production declines from mature fields. Oil production in Canada increased 7% in 2003 to a record volume of 51,767 barrels per day. The 2003 production increase was primarily related to higher volumes produced offshore Newfoundland at the Terra Nova and Hibernia fields. Production at Terra Nova increased 26% and averaged 15,712 barrels per day in 2003. Hibernia production increased by 11% to 12,822 barrels per day in 2003. Net production from the synthetic oil operation known as Syncrude fell 879 barrels per day, or 8%, in 2003 due to less efficient operations caused by more downtime for repairs. Production of light oil decreased 568 barrels per day, or 17%, due to continued field decline and various property sales during the year. Heavy oil production in Canada increased 478 barrels per day, or 5%, during 2003 due to the results of development drilling, which was partially offset by lower production from various properties sold during the year. U.K. production was down by 3,616 barrels per day, or 20%, primarily due to sale of the Ninian and Columba fields in mid-2003 and production decline at the Mungo/Monan field. The Company produced 5,172 barrels of oil per day in Ecuador, 14% higher than in 2002, primarily due to a new heavy oil pipeline that began operations in the last half of 2003. Production began at the Company’s West Patricia field in Block SK 309, offshore Sarawak Malaysia, in May 2003. Net production from West Patricia averaged 7,301 barrels per day for all 2003, but averaged over 11,000 barrels per day since start-up.

During 2002, oil production from continuing operations in the United States declined 13% compared to 2001 and averaged 4,128 barrels per day. The reduction was due to declines from existing fields in the Gulf of Mexico. Oil production in Canada increased 34% in 2002 to 48,239 barrels per day. The Company’s share of net production at its synthetic oil operation improved 883 barrels per day, or 8%, in 2002 due to a combination of higher gross production and a lower net profit royalty caused by increased capital spending related to an ongoing expansion project. Production of light oil decreased 982 barrels per day, or 23%, and heavy oil production decreased 19% to 9,484 barrels per day in 2002 with both decreases primarily due to declines at existing Western Canada fields. Production at Hibernia rose 21% in 2002 to 11,574 barrels per day due to better operating efficiency, primarily associated with improved handling of gas production. The Terra Nova field started up in January 2002 and averaged 12,463 barrels per day in 2002. U.K. production was down by 1,912 barrels per day, or 9%, in 2002 primarily due to declines from the Company’s “T” Block and Ninian fields in the North Sea. Oil production in Ecuador was 15% lower than 2001 and totaled 4,544 barrels per day. This reduction was caused by more pipeline constraints, which forced the operation to limit daily production.

Worldwide sales of natural gas from continuing operations were 215.3 million cubic feet per day in 2003, 292.9 million in 2002 and 278.3 million in 2001. The total for 2002 was a Company record for natural gas sales. Sales of natural gas in the United States were 82.3 million cubic feet per day in 2003, 88.1 million in 2002 and 112.6 million in 2001. The reductions in 2003 and 2002 were due to lower deliverability from mature fields in the Gulf of Mexico. Natural gas sales in Canada fell from a record level of 197.9 million cubic feet per day in 2002 to 123.5 million in 2003. The 38% reduction in 2003 was mostly caused by a steep production decline at the Ladyfern field. Canadian natural gas sales had increased 30% in 2002 due to higher production from the Ladyfern field. Natural gas sales in the United Kingdom were 9.6 million cubic feet per day in 2003, up 37% compared to 2002. U.K. natural gas sales in 2002 decreased 47% compared to 2001 levels and totaled 7 million cubic feet per day. The change in U.K. sales in each year was due primarily to the level of sales nominations at the Amethyst field in the North Sea.

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Worldwide crude oil sales prices were higher in 2003 than in 2002 due to a strengthening world economy and effective production output controls by OPEC producers. The Company’s average realized sales price for crude oil and condensate was $25.27 per barrel in 2003 compared to $23.59 in 2002. The worldwide average price was reduced $2.25 per barrel by the effects of the Company’s 2003 hedging program. The Company had hedged the sales price in 2003 for most of its heavy oil production in Canada and light oil production in the U.S., as well as a portion of its offshore and synthetic crude production in Canada. The U.S. average crude oil sales price was essentially flat with 2002 and averaged $24.22 per barrel. Light oil production in Canada was sold at an average of $27.39 per barrel in 2003, up 21% from 2002. Heavy Canadian oil sold at $12.34 per barrel in 2003, 27% lower than in 2002. The average 2003 sales prices for offshore and synthetic oil production in Canada were $27.08 per barrel and $24.97 per barrel, respectively. Offshore prices were 7% higher than 2002, but synthetic crude was lower by 3%. The average sales price in the U.K. increased by 21% to $29.59 per barrel. Ecuador production was sold at an average of $22.99 per barrel, which was 17% above the average for 2002. New production from the West Patricia field in Malaysia brought an average of $29.42 per barrel in 2003.

The average sales price for light crude oil in 2002 was comparable to 2001; however, heavy oil prices were significantly stronger in comparison to light oil prices during the year. In the United States, the Company’s average monthly sales price for crude oil and condensate declined 3% compared to 2001 and averaged $24.25 per barrel for the year. In Canada, the sales price for light oil rose 1% to $22.60 per barrel. Heavy oil prices in Canada averaged $16.82 per barrel, up 52% from 2001. The sales price for crude oil from the Hibernia field rose 7% to $25.34 per barrel. The average sales price for oil from the new Terra Nova field was $25.38 per barrel. Synthetic oil prices in 2002 were $25.64 per barrel, up 2% from the prior year. Sales prices in the U.K. were about flat with 2001 at $24.39 per barrel and sales prices in Ecuador were up 16% to $19.64 per barrel.

The sales prices for natural gas were much stronger in 2003 than in 2002 as high demand coupled with a tight supply buoyed prices. The average sales price realized by the Company in North America in 2003 was 64% higher than in 2002 and averaged $4.83 per thousand cubic feet (MCF) for the year. This price was reduced by $.17 per MCF because of the Company’s hedging program in the U.S. and Canada. In the U.S., natural gas sales prices averaged $5.29 per MCF in 2003, up 57% compared to 2002. Canadian gas prices increased 65% to an average of $4.52 per MCF. Natural gas was sold in the U.K. at an average of $3.50 per MCF, 27% higher than the 2002 average.

During 2002, the Company’s North American natural gas sales prices were weaker than in 2001 generally due to a warmer than normal winter. Natural gas sales prices in North America decreased 24% from 2001 and averaged $2.94 per MCF in 2002 compared to $3.87 in the prior year. U.S. natural gas sales prices decreased 27% in 2002 and averaged $3.37 per MCF compared to $4.64 in the prior year. Canadian natural gas production was sold in 2002 at an average price of $2.74 per MCF, 16% lower than in 2001. The sales price for natural gas sold in the United Kingdom increased 10% to $2.76 per MCF.

Based on 2003 volumes and deducting taxes at marginal rates, each $1 per barrel and $.10 per MCF fluctuation in prices would have affected earnings from exploration and production operations by $19.7 million and $4.6 million, respectively. The effect of these price fluctuations on consolidated net income cannot be measured because operating results of the Company’s refining and marketing segments could be affected differently.

Production expenses were $234.2 million in 2003, $229.6 million in 2002 and $211 million in 2001. These amounts are shown by major operating area on pages F-38 and F-39 of this Form 10-K report. Costs per equivalent barrel excluding discontinued operations during the last three years are shown in the following table.

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The lower costs in the United States in 2003 were due to both higher production and less well servicing costs. The increase in the cost per equivalent barrel in the U.S. in 2002 was attributable to a combination of lower production and more well servicing. Higher average Canadian costs excluding synthetic oil in 2003 was caused by lower natural gas production and a higher average foreign exchange rate. The lower average cost in 2002 for Canada, excluding synthetic oil, was due to higher natural gas production volumes and new production from the Terra Nova field, offshore Newfoundland. The increase in unit costs for Canadian synthetic oil operations in 2003 was attributable to a combination of lower production, higher maintenance costs and a higher foreign exchange rate. The lower average cost per barrel for Canadian synthetic oil in 2002 was due to a combination of lower maintenance costs and higher net production. Lower average costs in the U.K. in 2003 was mainly due to the sale of the high-cost Ninian and Columba fields in the second quarter. The increase in average costs in the U.K. in 2002 was due to both higher costs to maintain mature properties, primarily at the Ninian field, and lower overall production. Production expense increases per unit in Ecuador in 2003 were mostly attributable to higher transportation costs associated with the new heavy oil pipeline. Higher costs per unit in Ecuador in 2002 were due to lower oil production compared to the previous year.

Exploration expenses for each of the last three years are shown in total in the following table, and amounts are reported by major operating area on pages F-38 and F-39 on this Form 10-K report. Certain of the expenses are included in the capital expenditures total for exploration and production activities.

Dry hole costs were $18.7 million lower in 2003 than 2002 primarily due to more drilling success in deepwater Malaysia blocks. The $18.4 million increase in dry hole costs in 2002 was caused by higher costs for unsuccessful exploration drilling wells in the deep waters of the Gulf of Mexico and Malaysia, which were offset in part by lower costs in 2002 for wells off the east coast of Canada. Geological and geophysical expenses were up $10.6 million in 2003 mostly due to 3D seismic acquisition and processing in Blocks SK 309 and PM 311 in Malaysia. Geological and geophysical costs were down $12.6 million in 2002 due to less spending for 3D seismic on deepwater concessions in Malaysia. Other exploration expenses were $2.8 million lower in 2003 because more administrative costs in Malaysia were charged to the production department after start-up of West Patricia field production in May. Other exploration expenses were $4.8 million lower in 2002 primarily due to more charges to the Company’s partner in Malaysia. Undeveloped leasehold amortization increased by $2.6 million in 2003 and $1.5 million in 2002 primarily because of lease acquisitions in each year in the Gulf of Mexico and Western Canada.

A total cost of $5 million was incurred in 2002 to repair equipment and well damages caused by tropical storms in the Gulf of Mexico. These costs essentially represent amounts not recovered through insurance policies.

Depreciation, depletion and amortization expense related to exploration and production operations totaled $268.2 million in 2003, $247.2 million in 2002 and $181.1 million in 2001. The $21 million increase in 2003 compared to 2002 was caused primarily by start-up of the West Patricia field in 2003. Higher costs of $66.1 million in 2002 were caused by higher oil and natural gas production, including start up of the Terra Nova field in January 2002 and more production from the Ladyfern field in Western Canada.

The exploration and production business recorded $12.3 million of expense in 2003 for accretion on discounted abandonment liabilities following the adoption of SFAS No. 143 on January 1, 2003. Because the abandonment liabilities are carried on the balance sheet at a discounted fair value, accretion must be recorded annually so that the liability will be recorded at full value at the projected time of abandonment.

Property impairments occurred in the United States in each of the three years ended December 31, 2003. The amount of impairments in 2002 was significantly higher than 2003 and 2001 because the Company wrote off its remaining investment of $22.5 million in Destin Dome Blocks 56 and 57, offshore Florida. Based on an agreement with the U.S. government, the Company may not seek approval for development of this significant natural gas discovery until at least 2012.

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The effective income tax rate for exploration and production operations was 32.9% in 2003, 38.4% in 2002 and 39.9% in 2001. The lower rate in 2003 was attributable to several factors. The Company sold its interests in the Ninian and Columba fields in 2003. Profits on these fields were assessed Petroleum Revenue taxes in addition to normal corporation taxes; thus the sale of these fields reduced the overall effective tax rate in the U.K. In addition, the Company recorded an $11.4 million deferred tax credit in 2003 to recognize anticipated future tax benefits on previously incurred expenses related to Blocks SK 309 and 311 in Malaysia. These benefits had not been recognized in the income statement in previous years because the Company had established a deferred tax valuation allowance until such time that it became probable that these expenses would be used to offset future taxable income. Also in 2003, both the Federal and Alberta governments of Canada reduced their tax rates for oil and gas companies. The rate reductions led to recognition of an $11.8 million tax benefit, mostly related to a reduction in deferred income tax liabilities. The effective tax rate in 2002 was lower than in 2001 primarily due to higher benefits in the latter year from settlement of prior-year tax matters.

Approximately 69% of the Company’s U.S. proved oil reserves and 39% of the U.S. proved natural gas reserves are undeveloped. At December 31, 2003, about 93% of the total U.S. undeveloped reserves on a barrel of oil equivalent basis relate to deepwater Gulf of Mexico fields, including Medusa, Habanero and Front Runner. The Medusa and Habanero fields came on stream in November 2003 and a portion of the wells were not completed and/or producing at year-end. Front Runner is currently projected to produce first oil in the second half of 2004. In addition, 73% of oil reserves in Block SK 309 in Malaysia are undeveloped, pending further development drilling in future years. On a worldwide basis, the Company has spent approximately $280 million in 2003, $239 million in 2002 and $208 million in 2001 to develop proved reserves. The Company expects to spend about $220 million in 2004, $118 million in 2005 and $66 million in 2006 to move currently undeveloped proved reserves to the developed category.

The U.S. Securities and Exchange Commission (SEC) has obtained information from Murphy and other oil and gas companies operating in the Gulf of Mexico to assess how the industry is determining proved reserves related to new field discoveries. SEC regulations allow oil companies to recognize proved reserves if economic producibility is supported by either an actual production test or a conclusive formation test. In the absence of a production test, compelling technical data must exist to recognize proved reserves related to the initial discovery of the oil or natural gas field. Production tests in deepwater environments are extremely expensive and the oil industry has increasingly depended on advanced technical testing to support economic producibility. Murphy has recorded proved reserves related to four deepwater Gulf of Mexico fields based on conclusive formation tests rather than actual production tests. At the end of 2003, proved reserves for these four fields totaled 89.2 million barrels of oil equivalent, or approximately 21% of the Company’s worldwide proved reserves, including synthetic oil. Two of the fields are currently partially on production and the third is being developed, with expected first production for the latter field in the second half of 2004. Murphy believes the proved reserves are properly classified. Murphy has furnished the information requested by the SEC and is unable to predict the outcome of the SEC’s staff review of the industry’s practices. This issue is not expected to have a material effect on the Company’s financial results. If the issue is not favorably resolved, the Company may be required to revise the manner in which it reports its proved reserves, which could affect its finding costs per barrel and reserve replacement ratios.

Refining and Marketing – The Company’s refining and marketing operations lost $11.2 million in 2003 and $39.9 million in 2002. Earnings from this business were a record $153.7 million in 2001, including gains on asset sales. The 2003 loss from refining and marketing operations was lower than the 2002 loss by $28.7 million primarily due to better margins from the gasoline retail business in North America and the refining and marketing business in the United Kingdom. Overall, the Company’s U.S. refining margins continued to be squeezed in 2003, primarily due to the high price of crude oil that the Company was not able to completely pass on to wholesale and other refinery customers. In addition to higher average fuel margins in 2003 at North American retail gasoline stations, the Company’s profits from merchandise sales at these gasoline stations were also better in 2003.

During 2002, the unfavorable refining and marketing results were generally due to two reasons – extremely weak refining margins throughout most of the year in both the United States and United Kingdom, and a $71 million gain in 2001 on sale of the Company’s former Canadian pipeline and trucking operations. Crude oil feedstock prices at the Company’s U.S. and U.K. refineries were higher in 2002 than in 2001 and the increase in wholesale and retail sales prices for refined products in 2002 did not match the increased costs of crude oil in the markets served by the Company. Prior to the sale of the Canadian operations, this business generated a profit of $3.8 million in 2001.

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Geographically, the North American refining and marketing operations lost $21.2 million in 2003 and $39.2 million in 2002, following a profit of $139.6 million in 2001, which included the $71 million gain on sale of Canadian assets. North American operations include refining activities in the United States and marketing activities in the United States and Canada. It also formerly included pipeline and trucking operations in Canada prior to the sale of this business in 2001. Operations in the U.K. generated a profit of $10 million in 2003, but lost $.7 million in 2002. This business earned $14.1 million in 2001.

Unit margins (sales realizations less costs of crude oil, other feedstocks, refining operating expenses and depreciation and transportation to point of sale) averaged $1.60 per barrel in North America in 2003, $.80 in 2002 and $3.12 in 2001. North American product sales volumes increased 30% to a record 229,876 barrels per day in 2003. Sales volumes through the Company’s retail gasoline network at Wal-Mart stores continued to grow steadily throughout 2003. The Company’s North American refined product sales volume of 176,427 barrels per day in 2002 was 1% higher than in 2001. Higher sales volumes by the retail gasoline network in 2002 compared to 2001 were mostly offset by lower sales volumes in the wholesale market caused by lower finished products produced by the Company’s U.S. refineries.

Unit margins in the United Kingdom averaged $2.86 per barrel in 2003, $1.70 per barrel in 2002 and $3.29 in 2001. Sales of petroleum products were up 2% in 2003 following a 10% increase in 2002. Both years’ increases were caused by higher volumes sold in the cargo market.

U.S. refining and marketing operations were experiencing losses in early 2004 due to continued weak unit margins during this period.

Based on sales volumes for 2003 and deducting taxes at marginal rates, each $.42 per barrel ($.01 per gallon) fluctuation in the unit margins would have affected annual refining and marketing profits by $25.6 million. The effect of these unit margin fluctuations on consolidated net income cannot be measured because operating results of the Company’s exploration and production segments could be affected differently.

Corporate – The costs of corporate activities, which include interest income, interest expense and corporate overhead not allocated to operating functions, were $13.8 million in 2003, $23.6 million in 2002 and $12.8 million in 2001. Net after-tax corporate costs were $9.8 million lower in 2003 mainly due to a $20.1 million benefit from settlement of previous years’ income tax audit issues and lower net interest expense. These cost savings were partially offset by higher general and administrative expenses, including costs related to the Company’s retirement and incentive compensation plans. The higher net cost of $10.8 million in 2002 compared to 2001 was due to a combination of more net interest expense associated with higher borrowings and lower interest income earned.

Capital Expenditures

As shown in the selected financial data on page 10 of this Form 10-K report, capital expenditures, including discretionary exploration expenditures, were $979.2 million in 2003 compared to $868.1 million in 2002 and $864.4 million in 2001. These amounts included $123.9 million, $134.8 million and $133.8 million of exploration costs that were expensed. Capital expenditures for exploration and production activities totaled $762.7 million in 2003, 78% of the Company’s total capital expenditures for the year. Exploration and production capital expenditures in 2003 included $24.4 million for acquisition of undeveloped leases, $196.7 million for exploration activities, and $541.6 million for development projects. Development expenditures included $185.4 million for development of deepwater discoveries in the Gulf of Mexico; $111.2 million for the West Patricia and Kikeh fields in Malaysia; $28.3 million for the Terra Nova and Hibernia oil fields, offshore Newfoundland; $93.8 million for expansion of synthetic oil operations at the Syncrude project in Canada; and $62.5 million for Western Canada projects. Exploration and production capital expenditures are shown by major operating area on page F-37 of this Form 10-K report.

Refining and marketing capital expenditures totaled $215.4 million in 2003, compared to $234.7 million in 2002 and $175.2 million in 2001. These amounts represented 22%, 27% and 20% of total capital expenditures of the Company in 2003, 2002 and 2001, respectively. Refining capital spending was $130.8 million in 2003, compared to $150.1 million in 2002 and $88.9 million in 2001. The Company completed in 2003 its expansion of the Meraux, Louisiana refinery, which included building a hydrocracker unit to meet future clean fuel specifications and expanding the crude oil processing capacity of the plant to 125,000 barrels per day. Capital expenditures related to this expansion project amounted to $69 million in 2003, $116.2 million in 2002 and $55.1 million in 2001. Marketing expenditures amounted to $84.6 million in 2003 and 2002, and $86.3 million in 2001. The majority of marketing expenditures in each year was related to construction of retail gasoline stations at Wal-Mart sites in 21 states in the U.S. The Company began building gasoline stations at Wal-Mart stores in Canada in 2002. The Company opened 119 total stations in the U.S. and Canada in 2003, 125 in 2002 and 111 in 2001.

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Cash Flows

Cash provided by continuing operations was $652.3 million in 2003, $527 million in 2002 and $630.6 million in 2001. The increase in cash provided in 2003 was primarily due to higher crude oil and refined product sales volumes, and higher sales prices for crude oil, natural gas and refined products. Cash provided by operating activities was reduced by expenditures for refinery turnarounds and abandonment of oil and gas properties totaling $66.5 million in 2003, $15.2 million in 2002 and $16.4 million in 2001. Scheduled plant-wide turnarounds occurred at both U.S. refineries in 2003.

Cash proceeds from property sales were $188.6 million in 2003, $68.1 million in 2002 and $173 million in 2001. The 2003 property sales included the disposal of the Ninian and Columba fields in the U.K. and various oil and gas assets in Canada and the Gulf of Mexico. Borrowings under notes payable and other long-term debt, which were primarily used to fund a portion of the Company’s development capital expenditures, provided $309.7 million of cash in 2003, $407.6 million in 2002 and $88.2 million in 2001. Additional borrowings were lower in 2003 than in 2002 because of higher operational cash flow and higher proceeds from asset sales in the latter year. Cash proceeds from stock option exercises and employee stock purchase plans amounted to $3.6 million in 2003, $25.1 million in 2002 and $18.9 million in 2001.

Property additions and dry hole costs required $937.8 million of cash in 2003, $834.1 million in 2002 and $810.2 million in 2001. More field development expenditures in the deepwater Gulf of Mexico and at the West Patricia and Kikeh fields in Malaysia mostly accounted for the 2003 increase. Cash outlays for debt repayment during the three years included $76.8 million in 2003, $57.8 million in 2002 and $77.7 million in 2001. Larger debt repayments in 2003 were related to nonrecourse debt associated with the Company’s Hibernia field. Certain of the nonrecourse debt was repaid using available free cash flow as required by the nonrecourse debt agreement at Hibernia. Free cash flow increased due to a higher average sales price and higher production levels in 2003. Cash used for dividends to stockholders was $73.5 million in 2003, $70.9 million in 2002 and $67.8 million in 2001. The Company raised its annualized dividend rate from $.75 per share to $.80 per share beginning in the third quarter of 2002.

Financial Condition

Year-end working capital totaled $228.5 million in 2003, $136.3 million in 2002 and $38.6 million in 2001. The current level of working capital does not fully reflect the Company’s liquidity position as the carrying values for inventories under last-in first-out accounting were $156 million below fair value at December 31, 2003. Cash and cash equivalents at the end of 2003 totaled $252.4 million compared to $165 million a year ago and $82.7 million at the end of 2001.

Long-term debt increased by $227.5 million during 2003 to $1.09 billion at the end of the year, 35.5% of total capital employed. Long-term debt included $28.9 million of nonrecourse debt incurred in connection with the acquisition and development of the Hibernia oil field. The increase in long-term debt in 2003 was attributable to new borrowings associated with the Company’s capital expenditure program, including deepwater Gulf of Mexico development projects, continued expansion of the Syncrude plant, development of fields in Malaysia, and an expansion project at the Company’s Meraux, Louisiana refinery that was completed by year-end 2003. Long-term debt totaled $862.8 million at the end of 2002 compared to $520.8 million at December 31, 2001. Stockholders’ equity was $1.95 billion at the end of 2003 compared to $1.59 billion a year ago and $1.5 billion at the end of 2001. A summary of transactions in stockholders’ equity accounts is presented on page F-5 of this Form 10-K report.

Murphy had commitments of $456.4 million for capital projects in progress at December 31, 2003, including $38.9 million for costs to develop deepwater Gulf of Mexico fields, $84.2 million for continued expansion of synthetic oil operations in Canada, and $117.4 million for future work commitments in Malaysia.

The primary sources of the Company’s liquidity are internally generated funds, access to outside financing and working capital. The Company typically relies on internally generated funds to finance the major portion of its capital and other expenditures, but maintains lines of credit with banks and borrows as necessary to meet spending requirements. At December 31, 2003, the Company had access to short-term and long-term revolving credit facilities in the amount of $700 million. Of this amount, $150 million of revolving facilities had been drawn at year-end 2003. The most restrictive covenants under these facilities limit the Company’s long-term debt to capital ratio (as defined in the agreements) to 60%. At December 31, 2003, the long-term debt to capital ratio was approximately 36%. The Company also has unused uncommitted credit lines of approximately $94 million at December 31, 2003. In addition, the Company has a shelf

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registration on file with the U.S. Securities and Exchange Commission that permits the offer and sale of up to $650 million in debt and equity securities. Current financing arrangements are set forth more fully in Note E to the consolidated financial statements. At present, the Company does not anticipate utilizing a significant amount of its long-term borrowing capacity in 2004 as proceeds from the intended sale of Western Canada assets and normal cash flow from operations are expected to essentially cover the Company’s capital expenditure program. At March 1, 2004 the Company’s long-term debt rating by Standard and Poor’s was “A-” and by Moody’s was “Baal”. The Company’s ratio of earnings to fixed charges was 6.8 to 1 in 2003, 3.2 to 1 in 2002 and 11.3 to 1 in 2001.

Environmental

Murphy and other companies in the oil and gas industry are subject to numerous federal, state, local and foreign laws and regulations. The most significant of those laws and the corresponding regulations affecting the Company’s operations are:

These acts and their associated regulations set limits on emissions and, in the case of discharges to water, establish water quality limits. They also, in most cases, require permits in association with new or modified operations. Many states also have similar statutes and regulations governing air and water, which in some cases impose additional and more stringent requirements. Murphy is also subject to certain acts and regulations primarily governing remediation of wastes or oil spills. The applicable acts are:

The Company is also involved in personal injury and property damage claims, allegedly caused by exposure to or by the release or disposal of materials manufactured or used in the Company’s operations.

The Company operates or has previously operated certain sites and facilities, including three refineries, five terminals, and approximately 82 service stations, for which known or potential obligations for environmental remediation exist. In addition the Company operates or has operated numerous oil and gas fields that may require some form of remediation.

Under the Company’s accounting policies, an environmental liability is recorded when such an obligation is probable and the cost can be reasonably estimated. If there is a range of reasonably estimated costs, the most likely amount will be recorded, or if no amount is most likely, the minimum of the range is used. Recorded liabilities are reviewed quarterly. Actual cash expenditures often occur one or more years after a liability is recognized.

The Company’s liability for remedial obligations includes certain amounts that are based on anticipated regulatory approval for proposed remediation of former refinery waste sites. If regulatory authorities require more costly alternatives than the proposed processes, future expenditures could exceed the accrued liability by up to an estimated $3 million.

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The U.S. Environmental Protection Agency (EPA) currently considers the Company to be a Potentially Responsible Party (PRP) at two Superfund sites. The potential total cost to all parties to perform necessary remedial work at these sites may be substantial. Based on currently available information, the Company has reason to believe that it is a de minimus party as to ultimate responsibility at both Superfund sites. The Company has not recorded a liability for remedial costs on Superfund sites. The Company could be required to bear a pro rata share of costs attributable to nonparticipating PRPs or could be assigned additional responsibility for remediation at the two sites or other Superfund sites. The Company does not believe that the ultimate costs to clean-up the two Superfund sites will have a material adverse effect on its net income or cash flows in a future period.

There is the possibility that environmental expenditures could be required at currently unidentified sites, and new or revised regulations could require additional expenditures at known sites. However, based on information currently available to the Company, the amount of future remediation costs incurred at known or currently unidentified sites is not expected to have a material adverse effect on future net income or cash flows.

Certain environmental expenditures are likely to be recovered by the Company from other sources, primarily environmental funds maintained by certain states. Since no assurance can be given that future recoveries from other sources will occur, the Company has not recorded a benefit for likely recoveries at December 31, 2003.

The Company’s refineries also incur costs to handle and dispose of hazardous waste and other chemical substances. The types of waste and substances disposed of generally fall into the following categories: spent catalysts (usually hydrotreating catalysts); spent/used filter media; tank bottoms and API separator sludge; contaminated soils; laboratory and maintenance spent solvents; and various industrial debris. The costs of disposing of these substances are expensed as incurred and amounted to $3.5 million in 2003. In addition to these expenses, Murphy allocates a portion of its capital expenditure program to comply with environmental laws and regulations. Such capital expenditures were approximately $140.9 million in 2003 and are projected to be $65.7 million in 2004.

Other Matters

Impact of inflation – General inflation was moderate during the last three years in most countries where the Company operates; however, the Company’s revenues and capital and operating costs are influenced to a larger extent by specific price changes in the oil and gas and allied industries than by changes in general inflation. Crude oil and petroleum product prices generally reflect the balance between supply and demand, with crude oil prices being particularly sensitive to OPEC production levels and/or attitudes of traders concerning supply and demand in the near future. Natural gas prices are affected by supply and demand, which to a significant extent are affected by the weather and by the fact that delivery of gas is generally restricted to specific geographic areas. Because crude oil and natural gas sales prices were strong during 2003 and early 2004, prices for oil field goods and services could be adversely affected in the future. Due to the volatility of oil and natural gas prices, it is not possible to determine what effect these prices will have on the future cost of oil field goods and services.

Accounting changes and recent accounting pronouncements – As described in Note B on page F-10 of this Form 10-K report, Murphy adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, effective January 1, 2001 and SFAS No. 143, Accounting for Asset Retirement Obligations, effective January 1, 2003. Upon adoption of SFAS No. 143, the Company recorded an after-tax charge of $7 million, which was reported as the cumulative effect of a change in accounting principle. Adoption of SFAS Nos. 133/138 resulted in a transition adjustment gain to Accumulated Other Comprehensive Loss (AOCL) of $6.6 million, net of $2.8 million in income taxes, for the cumulative effect on prior years; there was no cumulative effect on earnings.

On January 1, 2003, the Company adopted SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections, and SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS No. 145 amends existing guidance on reporting gains and losses on the extinguishment of debt to prohibit the classification of the gain or loss as extraordinary and also amends SFAS No. 13 to require sale-leaseback accounting for certain lease modifications that have economic effects similar to sale-leaseback transactions. SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity. The adoption of these two accounting standards did not have a material effect on the Company’s financial statements.

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Additionally, beginning January 1, 2003, the Company has applied Financial Accounting Standards Board (FASB) Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirement for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an Interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34, and FASB Interpretation No. 46, Consolidation of Variable Interest Entities, an interpretation of ARB No. 51. Interpretation No. 45 elaborates on the disclosures to be made by a guarantor in its financial statements about its obligations under guarantees issued and requires under certain circumstances a guarantor to recognize, at inception of a guarantee, a liability for the fair value of the obligation undertaken. Interpretation No. 46 addresses the consolidation by business enterprises of variable interest entities as defined in the Interpretation. FASB Interpretation No. 46 was revised in December 2003 to provide further guidance about consolidation of variable interest entities. Application of this revised interpretation is effective for year-end 2003 for entities considered to be special-purpose entities as defined, or otherwise beginning in 2004 for other entities subject to the revised interpretation. The application of these FASB Interpretations did not have a material effect on the Company’s financial statements.

In December 2002, the FASB issued SFAS No. 148, Accounting for Stock-Based Compensation - Transition and Disclosure, an amendment of FASB Statement No. 123. This Statement amends SFAS No. 123, Accounting for Stock-Based Compensation, to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements. The annual disclosures are included in the notes to these consolidated financial statements.

In April 2003, the FASB issued SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments and for hedging activities under SFAS 133, Accounting for Derivatives and Hedging Activities. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, with all provisions applied prospectively. The Company’s adoption of this statement did not have any impact on the Company’s financial statements.

In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This statement established standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify an instrument that is within its scope as a liability. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective July 1, 2003. The adoption of SFAS 150 had no impact on the Company’s financial statements as the Company had no financial instruments with characteristics of both liabilities and equity.

The FASB issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets in 2001. SFAS No. 141 requires that all business combinations after July 2001 be accounted for using the purchase method of accounting and that certain acquired intangible assets in a business combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with annual tests for impairment and that intangible assets other than goodwill be amortized over their useful lives. The Company adopted SFAS No. 141 upon its issuance and adopted SFAS No. 142 on January 1, 2002. The Company had goodwill of $64.9 million at December 31, 2003. Goodwill has been tested for impairment as required by SFAS No. 142 at year-end 2003. Amortization expense related to goodwill was $3.1 million for the year ended December 31, 2001.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which supercedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of, and the accounting and reporting provisions of APB Opinion No. 30, Reporting the Results of Operations–Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual, and Infrequently Occurring Events and Transactions. The Company adopted the provision of SFAS No. 144 effective January 1, 2002. The adoption of SFAS No. 144 had no impact on the Company’s financial statements.

The Company adopted Emerging Issues Task Force (EITF) Topic 02-3 in the fourth quarter 2002. This consensus required that gains and losses on all derivative instruments within the scope of SFAS No. 133 be shown net in the income statement if the derivatives are held for trading purposes. Accordingly, Murphy reflected the results of its crude oil trading activities as net revenue in its income statement and previously reported revenues and cost of sales were reduced by equal and offsetting amounts with no changes to net income or cash flows. The effect of this reclassification was a net reduction of both Sales and Other Operating Revenues and Crude Oil, Natural Gas and Product Purchases by approximately $269 million in 2002 and $600 million in 2001.

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In July 2003 the FASB undertook to review whether mineral interests in properties (mineral leases) held by oil and gas companies should be recorded and disclosed as intangible assets under the guidance of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. The FASB is considering whether an oil and gas company’s investment in mineral leases should be classified as intangible assets. SFAS No. 141 and SFAS No. 142 established new accounting guidelines for both finite lived intangible assets and indefinite lived intangible assets. Under SFAS No. 141 and SFAS No. 142, intangible assets should be separately reported on the Balance Sheet, with accompanying disclosures in the notes to the financial statements. SFAS No. 142 does not change the accounting prescribed in SFAS No. 19, Financial Accounting and Reporting by Oil and Gas Producing Companies, and is silent about whether its disclosure provisions apply to oil and gas companies. The Company does not believe that SFAS No. 141 and SFAS No. 142 change the classification and disclosure of oil and gas mineral leases and it continues to classify these assets as part of Property, Plant and Equipment in the Consolidated Balance Sheet and it does not provide the additional disclosures for these assets. The EITF has added the discussion of oil and gas mineral leases to its agenda, which may result in a change in the recording and disclosure of oil and gas mineral leases. Should the EITF determine that oil and gas mineral leases are intangible assets in accordance with SFAS No. 141 and SFAS No. 142, the Company would reclassify $143 million and $142 million as intangible undeveloped mineral interests at December 31, 2003 and 2002, respectively. In addition, a reclassification of $8 million and $7 million would be made as intangible developed mineral interests at December 31, 2003 and 2002, respectively. Both intangible assets would be presented net of accumulated amortization. Historically, undeveloped mineral leases have been amortized over the life of the lease period, while developed mineral leases have been amortized using the units of production method over the expected life of proved reserves. The amounts included herein are based on our understanding of the issue on the EITF’s agenda. If all mineral leases associated with oil and gas properties are deemed to be intangible assets in accordance with SFAS No. 141 and SFAS No. 142 by the EITF:

Significant accounting policies – In preparing the Company’s financial statements in accordance with accounting principles generally accepted in the United States, management must make a number of estimates and assumptions related to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities. Application of certain of the Company’s accounting policies requires significant estimates. The most significant of these accounting policies are described below.

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Contractual obligations and guarantees – The Company is obligated to make future cash payments under borrowing arrangements, operating leases, purchase obligations and other long-term liabilities. Total payments due after 2003 under such contractual obligations are shown below.

In the normal course of its business, the Company is required under certain contracts with various governmental authorities and others to provide financial guarantees or letters of credit that may be drawn upon if the Company fails to perform under those contracts. The amount of commitments that expire in future periods is shown below.

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Material off-balance sheet arrangements – The Company occasionally utilizes off-balance sheet arrangements for operational or funding purposes. The most significant of these arrangements at year-end 2003 involve an oil and natural gas processing contract and a hydrogen purchase contract. The processing contract provides crude oil and natural gas processing capacity for oil and natural gas production from the Medusa field in the Gulf of Mexico. Under the contract, the Company pays a specified amount per barrel of oil equivalent for processing its oil and natural gas through the facility. If actual oil and natural gas production processed through the facility through 2009 is less than a specified quantity, the Company must make additional quarterly payments up to an agreed minimum level that varies over time. The Company has committed to purchase hydrogen for the Meraux refinery from a third party through 2019. The contract requires a monthly minimum base facility charge whether or not any hydrogen is purchased. Payments under both these agreements are recorded as operating expenses when paid. Future required minimum annual payments under both of these arrangements are included in the contractual obligation table shown above.

Outlook

Prices for the Company’s primary products are often quite volatile. During 2003 and early 2004 crude oil prices remained strong primarily due to uncertainty in Iraq and the Middle East, coupled with an improving global economy and effective price management practices utilized by OPEC. High crude oil prices were a contributing factor to weak earnings and cash flows from the Company’s refining and marketing operations. Natural gas prices also were strong in 2003 and early 2004, mainly due to demand for the product often outstripping supply in the short term. Due to the volatility of worldwide crude oil prices and U.S. natural gas prices constant reassessment of spending plans is required.

The Company’s capital expenditure budget for 2004 was prepared during the fall of 2003 and provides for capital expenditures of $843 million. Of this amount, $650 million or 77%, is allocated for exploration and production. Geographically, 29% of the exploration and production budget is allocated to the United States, including $84 million for development of deepwater projects in the Gulf of Mexico; another 28% is allocated to Canada, including $32 million for continued development of the Hibernia and Terra Nova fields and $75 million for further expansion of synthetic oil operations; 37% is allocated to exploration and development in Malaysia; and the remaining 6% is planned for other areas, including Ecuador, the United Kingdom and the Republic of Congo. Budgeted refining and marketing capital expenditures for 2004 are $184 million, including $165 million in North America and $19 million in the United Kingdom. Planned spending in North America includes funds to build 160 additional gasoline stations at Wal-Mart sites. Capital and other expenditures are under constant review and planned capital expenditures may be adjusted to reflect differences between budgeted and actual cash flow during 2004.

In late 2003, the Company announced its intent to sell most of its conventional oil and natural gas properties in Western Canada. The properties expected to be sold produce approximately 20,000 barrels of oil equivalent per day. Marketing of the properties to be sold began in February, and the sale is expected to be completed in the second quarter of 2004. The gain or loss on the sale and the operating results of the properties to be sold are expected to be accounted for as discontinued operations beginning in 2004.

The Company currently does not anticipate a significant increase in long-term borrowings between year-ends 2003 and 2004. Although Murphy’s 2004 Budget includes a robust amount of capital spending, the Company expects the proceeds of the sale of Western Canada conventional oil and gas properties and normal operating cash flows to be sufficient to cover planned spending. It is possible that long-term debt could exceed the budgeted year-end 2004 levels, especially if the sales proceeds in Western Canada are less than anticipated or if cash flows are adversely affected in the upcoming months by significantly weaker oil and natural gas sales prices and continued weak refining and marketing margins such as those experienced in early 2004.

The Company has made significant oil discoveries in deep waters off Sabah, Malaysia. The Company is currently preparing a plan of development and considering its alternatives for funding the project. Although it is too early to predict the ultimate cost of the development project, it is likely that a significant portion of the Company’s share of funding will come from borrowed capital. Significant development costs are currently expected to begin in 2005. First production from the deepwater fields offshore Sabah is estimated to occur in 2007.

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Murphy’s oil production is expected to grow in 2004. The Medusa and Habanero fields in the deepwater Gulf of Mexico started up November 2003 and the West Patricia field in Malaysia came on line in May 2003. Production from the deepwater Gulf of Mexico fields will ramp up in early 2004. Another deepwater Gulf of Mexico field known as Front Runner is expected to come on production in the second half of 2004. These new fields are expected to more than offset normal production declines and the expected sale of Western Canada properties. Natural gas sales volumes are expected to decline in 2004 compared to 2003 levels. Total production for 2004 is projected to average approximately 130,000 barrels of oil equivalent per day.

Murphy Oil and certain of its subsidiaries maintain defined benefit retirement plans covering most of its full-time employees. During 2003, the Company reduced the expected investment return for assets held in its U.S. retirement plans from 8.0% to 7.5%. Due to a reduction in bond yields during 2003, the Company has also reduced the plans’ discount rates from 6.75% in 2003 to 6.25% in 2004. The funded status of the Company’s retirement plans was adversely affected over the last two years by changes in assumptions used to calculate plan liabilities. The smoothing effect of current accounting regulations tend to buffer the current year’s pension expense from wide swings in liabilities and asset returns. The effect of liability assumption changes will adversely impact the Company’s pension expense in 2004. The Company’s annual retirement plan expense is estimated to increase by about $2.5 million for 2004 compared to 2003. In 2004, the Company is required to fund payments of approximately $2.5 million into two funded retirement plans and expects to pay $1.1 million for two unfunded plans. The Company could be required to make additional and more significant funding payments to retirement plans in future years.

Forward-Looking Statements

This Form 10-K report, including documents incorporated by reference here, contains statements of the Company’s expectations, intentions, plans and beliefs that are forward-looking and are dependent on certain events, risks and uncertainties that may be outside of the Company’s control. These forward-looking statements are made in reliance upon the safe harbor provisions of the Private Securities Litigation Reform Act of 1995. Actual results and developments could differ materially from those expressed or implied by such statements due to a number of factors including those described in the context of such forward-looking statements as well as those contained in the Company’s January 15, 1997 Form 8-K report on file with the U.S. Securities and Exchange Commission.

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Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is exposed to market risks associated with interest rates, prices of crude oil, natural gas and petroleum products, and foreign currency exchange rates. As described in Note A to the consolidated financial statements, Murphy makes limited use of derivative financial and commodity instruments to manage risks associated with existing or anticipated transactions.

The Company was a party to interest rate swaps at December 31, 2003 with notional amounts totaling $50 million that were designed to hedge fluctuations in cash flows of a similar amount of variable-rate debt. These swaps mature in 2004. The swaps require the Company to pay an average interest rate of 6.17% over their composite lives, and at December 31, 2003, the interest rate to be received by the Company averaged 1.64%. The variable interest rate received by the Company under each swap contract is repriced quarterly. The Company considers these swaps to be a hedge against potentially higher future interest rates. The estimated fair value of these interest rate swaps was recorded as a liability of $1.8 million at December 31, 2003.

At December 31, 2003, 40% of the Company’s debt had variable interest rates and 2% was denominated in Canadian dollars. Based on debt outstanding at December 31, 2003, a 10% increase in interest rates on variable rate debt would increase the Company’s interest expense in 2004 by approximately $3.4 million after including the favorable effect resulting from lower net settlement payments under the aforementioned interest rate swaps. A 10% increase in the exchange rate of the Canadian dollar versus the U.S. dollar would increase interest expense in 2004 by less than $.1 million for debt denominated in Canadian dollars.

Murphy was a party to natural gas swap agreements at December 31, 2003 for a total notional volume of 9.2 MMBTU that were originally designated as a hedge of the financial exposure of its Meraux, Louisiana refinery to fluctuations in the future price of a portion of natural gas to be purchased for fuel during 2004 through 2006. In each month of settlement, the swaps require Murphy to pay an average natural gas price of $2.78 per MMBTU and to receive the average NYMEX price for the final three trading days of the month. At December 31, 2003, the estimated fair value of these agreements was recorded as an asset of $22.8 million. A 10% increase in the average NYMEX price of natural gas would have increased this asset by $4.7 million, while a 10% decrease would have reduced the asset by a similar amount. As described in Note J on Page F-24, at December 31, 2003, a portion of these agreements no longer qualified for hedge accounting and a portion of these agreements have been redesignated as a hedge of natural gas to be purchased by the Superior refinery in 2004.

Murphy is subject to foreign currency exchange risk, primarily because of its operations in Canada and the U.K. Fluctuations in foreign currencies affect reported revenues and operating costs, capital expenditures and assets and liabilities denominated in currencies other than the U.S. dollar. On occasion, the Company has used financial currency contracts to manage this risk. At December 31, 2003, the Company had $33 million in Canadian dollar forward contracts that matured within 30 days. The fair value of these contracts was recorded in income at the end of 2003 and did not significantly impact the Company’s financial statements.

Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information required by this item appears on pages F-1 through F-43, which follow page 31 of this Form 10-K report.

Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

Item 9A. CONTROLS AND PROCEDURES

The Company, under the direction of its principal executive officer and principal financial officer, has established controls and procedures to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

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Based on the Company’s evaluation as of the end of the period covered by the filing of this Annual Report on Form 10-K, the principal executive officer and principal financial officer of Murphy Oil Corporation have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15 under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by Murphy Oil Corporation in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no significant changes in the Company’s internal controls over financial reporting that occurred during the fourth quarter of 2003 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Certain information regarding executive officers of the Company is included on page 8 of this Form 10-K report. Other information required by this item is incorporated by reference to the Registrant’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2004 under the caption “Election of Directors.”

Murphy Oil has adopted a Code of Ethical Conduct for Executive Management, which can be found under the Corporate Governance and Responsibility tab at www.murphyoilcorp.com. Stockholders may also obtain free of charge a copy of the Code of Ethical Conduct for Executive Management by writing to the Company’s Secretary at P.O. Box 7000, El Dorado, AR 71731-7000. Any future amendments to or waivers of the Company’s Code of Ethical Conduct for Executive Management will be posted on the Company’s internet website.

Item 11. EXECUTIVE COMPENSATION

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2004 under the captions “Compensation of Directors,” “Executive Compensation,” “Option Exercises and Fiscal Year-End Values,” “Option Grants,” “Compensation Committee Report for 2003,” “Shareholder Return Performance Presentation” and “Retirement Plans.”

Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2004 under the captions “Security Ownership of Certain Beneficial Owners,” “Security Ownership of Management,” and “Equity Compensation Plan Information.”

Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None

Item 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Information required by this item is incorporated by reference to Murphy’s definitive Proxy Statement for the Annual Meeting of Stockholders on May 12, 2004 under the caption “Audit Committee Report.”

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PART IV

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

All other financial statement schedules are omitted because either they are not applicable or the required information is included in the consolidated financial statements or notes thereto.

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A report on form 8-K was filed on October 28, 2003 that included the Company’s News Release, announcing the Company’s earnings and certain other financial information as of and for the three-month and first nine-months periods that ended on September 30, 2003.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 12, 2004 by the following persons on behalf of the registrant and in the capacities indicated.

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REPORT OF MANAGEMENT

The management of Murphy Oil Corporation is responsible for the preparation and integrity of the accompanying consolidated financial statements and other financial data. The statements were prepared in conformity with generally accepted U.S. accounting principles appropriate in the circumstances and include some amounts based on informed estimates and judgments, with consideration given to materiality.

Management is also responsible for maintaining a system of internal accounting controls designed to provide reasonable, but not absolute, assurance that financial information is objective and reliable by ensuring that all transactions are properly recorded in the Company’s accounts and records, written policies and procedures are followed and assets are safeguarded. The system is also supported by careful selection and training of qualified personnel. When establishing and maintaining such a system, judgment is required to weigh relative costs against expected benefits. The Company’s audit staff independently and systematically evaluates and formally reports on the adequacy and effectiveness of the internal control system.

Our independent auditors, KPMG LLP, have audited the consolidated financial statements. Their audit was conducted in accordance with auditing standards generally accepted in the United States of America and provides an independent opinion about the fair presentation of the consolidated financial statements. When performing their audit, KPMG LLP considers the Company’s internal control structure to the extent they deem necessary to issue their opinion on the financial statements. The Board of Directors appoints the independent auditors; ratification of the appointment is solicited annually from the shareholders.

The Board of Directors appoints an Audit Committee annually to implement and to support the Board’s oversight function of the Company’s financial reporting, accounting policies, internal controls and independent outside auditors. This Committee is composed solely of directors who are not employees of the Company. The Committee meets routinely with representatives of management, the Company’s audit staff and the independent auditors to review and discuss the adequacy and effectiveness of the Company’s internal controls, the quality and clarity of its financial reporting, the scope and results of independent and internal audits, and to fulfill other responsibilities included in the Committee’s Charter. The independent auditors and the Company’s audit staff have unrestricted access to the Committee, without management presence, to discuss audit findings and other financial matters.

INDEPENDENT AUDITORS’ REPORT

The Board of Directors and Stockholders of Murphy Oil Corporation:

We have audited the accompanying consolidated balance sheets of Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of income, comprehensive income, stockholders’ equity and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Murphy Oil Corporation and Consolidated Subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note B to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations, effective January 1, 2002, the Company changed its method of accounting for goodwill and other intangible assets and effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities.

Shreveport, Louisiana

February 18, 2004

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MURPHY OIL CORPORATION AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME